ML16342C070
| ML16342C070 | |
| Person / Time | |
|---|---|
| Site: | Diablo Canyon  |
| Issue date: | 05/19/1994 |
| From: | Kirsch D NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML16342A515 | List: |
| References | |
| 50-275-94-11, 50-323-94-11, NUDOCS 9405250015 | |
| Download: ML16342C070 (48) | |
See also: IR 05000275/1994011
Text
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APPENDIX B
U.S.
NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report:
50-275/94-11
50-323/94-11
Operating Licenses:
DPR-82
Licensee:
Pacific
Gas
and Electric Company
Nuclear
Power Generation,
B14A
77 Beale Street,
Room 1451
San Francisco,
94177
Facility Name:
Diablo Canyon,
Units
1
and
2
Inspection At:
Diablo Canyon Site,
San Luis Obispo County, California
Inspection
Conducted:
March 20 through April 23,
1994
Inspectors:
M. Miller, Senior Resident
Inspector
H. Tschiltz, Resident
Inspector
Approved By.
D.
lrsc
,
1
Reactor Projects
Branch
E
Ins ection
Summar
te
ig
Areas
Ins ected
Units
1 and
2
Routine,
announced,
resident
inspection of
onsite followup of events,
operational
safety verification, plant maintenance,
surveillance observations,
refueling preparations
and operations,
quality
oversite activities, safety
system walkdown, followup on corrective actions
for violations, followup, and in-office review of licensee
event reports.
Results
Units
1 and
2
~0erations:
Operations
personnel
performed well during this inspection period.
Strengths:
Prompt conservative
actions
were
implemented
by the operations
department
to shut
down the Unit 2 reactor within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />
when
a leak
was identified in the reactor coolant
system
(RCS).
9405250015
940519
ADOCK 05000275
Q
PDQ-
Weakness:
~
Communications
and control of fuel movement
were inconsistent with
management's
expectations.
Haintenance:
Certain maintenance
activities were not conducted
in accordance
with
applicable
procedures
and management
expectations
during this inspection
period.
Weaknesses
~
Actions to repair the leak in the Unit 2 reactor'ere
not conducted
using the required clearance for control of the repair work boundary.
As
a result,
gas
was injected into the
RCS, which could have
resulted
in elevated
RCS activity and radiation levels.
~
Maintenance
management
had not clearly communicated
expectations
for
signing work orders to the construction
crew installing an inverter,
resulting in recorded
dates for installation work steps
being back-dated
to the date of performance,
rather than indicating the date of
signature.
Licensee
management
took prompt action to communicate
expectations
to construction
personnel
and, later, to maintenance
personnel.
The licensee's
engineering
organization
responded
well to the emergency
diesel
generator air flow concern;
however,
weakness
was observed
in the conduct of
(LLRT) and the evaluation of reduced diesel
generator
loading capability.
Strengths
The engineering
organizations
promptly responded
to concerns
regarding
EDG radiator airflow, contacted
industry experts,
conducted
intensive
testing of diesel
generator radiator air flow, took conservative
action
to recommend
delay of Unit 2 restart,
and maintained Unit 2 in cold
shutdown while
EDG operability testing
was ongoing.
This evidenced
a
conservative
safety perspective.
Weaknesses
~
The operations
and maintenance
organizations
identified inadequate
administrative controls of LLRT temporary modifications by engineering.
Plant management
took actions to clarify expectations
and implement
additional training for LLRT personnel.
-3-
The initial operability evaluation
associated
with Oiesel
Generator
1-3
declared
the diesel
generator
operable for Nodes
5 and
6 at reduced
electrical
loading without consideration
of Technical Specification
(TS)
requirements
for diesel
generator
loading during these
modes
and without
adequate
instruction to operators
regarding selection of electrical
loads which would be appropriate
to shed in the event of a derated
generator.
Licensee
management
agreed with inspectors that this
evaluation
was not appropriate,
and the evaluation
was revised.
The licensee's
quality oversight organization
performed well during this
inspection period.
Strengths
~
The quality organization
evidenced
strong, intrusive involvement,
problem identification,
and corrective action concerning
weaknesses
associated
with the maintenance
area.
Issues
included operability
evaluations of past
improper re-installation of motor-operated
valve
pinion keys,
inspections
to identify cracking in 480
V transformer
insulators,
improper temporary attachments
in the Unit
1 containment,
and lack of visual inspection of snubbers.
Summary of Inspection
Findings:
~
Violation 323/94-11-01
was identified (Section 4).
~
Violation 275/93-32-01
was closed
(Section
10).
~
Licensee
Event Reports
275/94-04,
Revision 0,
and 275/94-05,
Revision 0,
were closed
(Section
11).
Attachments:
~
Attachment
1 - Persons
Contacted
and Exit Neeting
~
Attachment
2 - Acronyms
DETAILS
1
PLANT STATUS
(71707)
1.1
Unit
1
The unit was shut
down throughout the entire inspection period for a refueling
outage
(1R6).
Core offload and reload operations
occurred during this period.
1.2
Unit 2
At the beginning of this inspection period, the unit was operating at
100 percent of rated thermal
power.
On March 26,
1994,
power was reduced to
50 percent to facilitate scraping of marine growth from the circulating water
Pump 2-1 tunnel.
On March 27,
1994,
the unit was shut
down after
identification of RCS leakage.
Following repair of the leak,
and
EDG radiator
air flow testing,
the unit transitioned to Mode
1
and returned to 100 percent
power on April 10,
1994.
2
OPERATIONAL EVENTS (93702)
2. 1
Unit 2 Unusual
Event
Due to Reactor
Coolant
S stem
Pressure
Boundar
Leaka
e
During
a containment entry for the purpose of troubleshooting
Pump 2-3 seal leakoff indication,
a leak was identified near Reactor Coolant
Pump 2-3, in an area containing piping from several
systems
normally
inaccessible
during reactor operation.
The location of the leak was initially
thought to be valve packing leakage
from the resistance
temperature
detector
(RTD) manifold isolation valve.
This was difficult to confirm due to the high
radiation levels in the area.
Operations
management
concluded that
a plant
shutdown
was prudent
and reached
Node
3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
Immediately after
reactor
shutdown,
on
a containment entry for further investigation,
the leak
location was determined to be not from the
nonisolable
cracked
socket weld on
a 3/4-inch vent line cornected to Safety
Injection Accumulator 2-3 injection line.
Operations
concluded that
a plant
shutdown would have
been required
by TS since the 0.3
gpm leak was nonisolable
pressure
boundary leakage.
An unusual
event
was declared.
Upon transition to
Mode
5 on March 28 1994, the licensee
terminated the unusual
event
and
began
establishing
conditions for repair of the leak.
Failure analysis of the
cracked weld, performed
by Westinghouse,
revealed that the cause of the leak
was
a weld defect
on the inner diameter of the weld,
an area not required to
be inspected
during fabrication.
2'.1
Conclusion
The licensee
operations staff initiated
a conservative
reactor plant shutdown
following discovery of the
RCS leak.
Immediately after reactor
shutdown,
a
more precise
leak location was identified.
The licensee
Operations staff
0
promptly declared
an Unusual
Event
upon determination that the leak was
unisolable
RCS leakage.
Evaluation of repair efforts are described
in
Paragraph
4.
2.2
Unantici ated
Hi
h Radiation Area Durin
Chemical
and Volume Control
S stem
S stem Fill and Vent
At about
4 p.m.
on April 11,
1994, the licensee identified that
a high
radiation area
had occurred in a radiologically controlled area hallway,
originating in reactor
cleanup piping mounted
along the hallway.
The area
was
posted
promptly upon discovery,
a root cause
evaluation initiated,
and
a
visiting NRC health physics inspector
and resident
inspectors
were informed.
Based
on the configuration of the radiation area localized to
a hot spot,
and
the low traffic in the area,
the licensee
determined that
no personnel
had
been over exposed.
Earlier that day, at 2:50 a.m.
on April 11, before
CVCS fill and vent
operations
had
commenced,
Operations
alerted Health Physics to the potential
for changing radiation
areas
caused
by the fill and vent.
Apparently no
radiation protection surveys
were accomplished
in that area after that
announcement
until the routine survey around
4 p.m. the
same day, which
identified the hot spot.
Licensee root cause
investigation determined that the area radiation levels
had risen sharply,
at approximately the time the
CVCS fill and vent procedure
had
been
underway, while testing the
CVCS diversion valve function.
The
licensee
determined
the most likely cause of the hot spot,
which is discussed
in the following paragraph.
Forced oxygenation,
which was performed before
shutdown to decrease
RCS piping
radiations levels,
probably caused
highly activated iron oxides
(magnetite)
to
deposit in the deborating demineralizer.
A newly replaced
0.2 micron filter
upstream of the hot spot
and downstream of the deborating demineralizer
was
later found to have failed.
It is likely that
a water slug was generated
by
the fill and vent procedure,
which could have
caused
the magnetite to break
loose
from the resin
bed
and travel to the filter.
The filter may have
ruptured at that time or an earlier time.
This would have allowed the
magnetite to travel past the filter to the area of piping which was the source
of the hot spot.
The filter vendor
and the licensee
concluded that the
filter, bowed out
as if overpressurized,
had
been
exposed to reverse flow,
since the normal flow path is from the outside of the cylindrical filter to
the inside of the filter.
A reverse
flow path
may have occurred during
hydrostatic testing of the volume control tank.
Check valve leakage
was
suspected
during the hydrostatic test.
Licensee investigation is continuing
and appears
to be conducted
in a thorough manner.
At the time that the hot spot
was identified,
no formal notification was
made
to the
NRC.
The licensee's
emergency
plan was not consistent with the safety
significance of the event,
since the only emergency
plan guidance available
was
ambiguous
and would have resulted
in a highly conservative
recommendation
of an Alert level of emergency
response.
The licensee
determined that
declaration of an Alert was incorrect,
since
no chance of off site radiation
release
was possible for this hot spot.
After inquiries from the
NRC, the
licensee later discussed
the basis for not declaring
an Alert with NRC
management.
The basis
appeared
appropriate.
The licensee
agreed to revise
the emergency
response
plan to more clearly and appropriately
address
these
types of situations.
The licensee's
corrective action in this area will be
reviewed during the next scheduled
NRC inspection of the emergency
response
area.
The health physics
aspects
of this issue
are addressed
by the
NRC inspection
report issued
by the Region-based
NRC health physics inspector.
The licensee
received
a violation for the unposted radiation area,
issued
in the
NRC hea)th
physics Inspection
Report 50-275/94-12;
50-323/94-12.
2.2.1
Conclusion
The licensee radiation protection organization did not appropriately
survey
for changes
in radiation levels
when warned
by the operations staff.
The root
cause of this deficiency will be followed by the
NRC hea')th physics
and
emergency
preparedness
inspection efforts.
Licensee investigation into the
cause of the hot spot was prompt
and appears
to be continuing in a
responsible,
appropriate
fashion.
Corrective action observed to date
appeared
appropriate.
3
OPERATIONAL SAFETY VERIFICATION
(71707)
3. 1
Control of Plant Confi uration
and Status of
E ui ment
Im lemented
in the
Control
Room
Inspectors
performed frequent control board walkdowns in the control
room to
observe
Operations
control of plant configuration, clarity of clearance
tags,
appropriate availability of plant equipment
and instrumentation
during
shutdown
and operating
modes,
and effective, conservative transitions
through
the various
modes of operation.
Both units transitioned
through several
operating
modes during this inspection period.
Inspectors
found operators
to
be knowledgeable
and control of plant equipment to be appropriate.
Equipment
tags clearly referenced
applicable clearances
and noted additional cautions
and restrictions.
The
TS and the outage safety plan was followed for both
units with respect
to availability of plant equipment.
3. 1. 1
Conclusion
The control
room boards
were maintained
in an appropriate
fashion during both
unit outages.
Control board indication
and control for plant equipment
and
instrumentation
were appropriately tagged,
and restrictions
were clearly
documented
or referenced for cases
where multiple safety controls were
applicable.
3.2
Ina
ro riate Documentation of Containment
LLRT Jum er
Jum er 94-019
On Harch
16, during routine Operations
department
review of the jumper logs,
operations identified that
a jumper had
been
documented
but had not received
proper reviews
by operations.
Operations
issued Action Request
A0331842 to
document
the deficiency.
Later review determined that the jumper supplied
pressure
for containment isolation valve local leak rate testing in
containment,
being performed
by engineering
and maintenance.
The pressurizing
gas
was supplied through the spare
Containment
80.
Further investigation revealed that poor communications
had occurred
between
Engineering
and Haintenance
concerning
jumper documentation
and existing
procedural
controls for the
LLRT, resulting in submission of incomplete jumper
documentation.
guality Evaluation
11270
was issued to determine the root
cause of the inadequate
communications.
Engineering
and maintenance
management
discussed
appropriate
expectations
and
controls for planning
and documentation
of LLRT jumpers,
as well as conduct of
LLRT evolutions, with their staffs.
To determine the safety significance,
the inspector evaluated existing
controls of the
LLRT process
regarding the jumper.
Further review determined
that the entire process of connection,
control, disconnection,
and use of the
jumper was controlled by several
plant procedures,
including:
Procedure
STP G-12, "Operation of the Portable
Leak Test Monitor," Revision 3;
several
procedures
for individual penetration testing,
such
as
Procedure
STP V-651A, Revision 3, "Penetration
51A Containment Isolation Valve
Leak Testing," which, for example,
included Step 11.3. 15 "replace seal
on
SI-1-153,"
and Step 11.3. 18 "verify removal of all test instrumentation," with
sign offs on each step.
The inspector questioned
whether the controls for ensuring
containment
integrity were established
for the spare penetration,
and noted that
Procedure
OP K-108,
"Sealed
Valve Checklist for Manual
Containment Isolation
Valves," Revision 3, Step 2. 1, stated
"This sealed
valve checklist verifies
inside containment
manual isolation valves are in the correct positions
and
sealed ... for Modes 1,2,3
and 4."
Step 6. 1 stated
"Visually verify position
of containment isolation valves in Appendix 9. 1," which included the
80 spare
instrument lines.
These controls
appeared
comprehensive
and appropriate.
The safety significance of the inadequate
jumper documentation
is very low in
that multiple levels of control of the jumper exist in plant procedures.
3,2. 1
Conclusion
Operations
promptly identified incorrect documentation of a plant jumper.
Engineering
and maintenance
management
took steps
to correct inadequate
communications
between
the two groups coordinating
LLRT work.
The safety
significance of this issue is low, but provides
an example of a communication
and work control problem identification and corrective action.
3.3
EDG Radiator Air Flow
Licensee testing of
EDG radiator air flow identified lower than expected
flow
values.
The licensee initiated several
tests of EDG air flow, including
testing of Unit 2
EDGs, during the unscheduled
Unit 2 shutdown.
The
engineering staff conservatively
required Unit 2 to remain shut
down until
operability was thoroughly addressed.
An operability evaluation
was issued
identifying that,
above the 78'F ambient design temperature,
air flow may not
be adequate
to remove heat from the radiator.
The Final Safety Analysis
Report design basis
concluded that temperatures
above 78'F would occur only
for 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> per year, with a maximum temperature
of 91
F.
Temperatures
at the
site
had not exceeded
78
F for
an extended
period.
On April 1,
1994, during
a review of EDG 1-3 operability evaluation,
documented
on Action Request
A0333816,
the inspector
noted that the licensee
concluded that the
with reduced radiator air flow during
Modes
5 and 6, provided generator
loading was maintained less
than
1400
kw.
The operability evaluation further stated that generator
loading could
be
increased
to above
1400
kw provided operations
monitored jacket water
temperature
every
30 minutes
and loads
were reduced
as reqiiired to maintain
diesel
engine jacket water temperature
less
than 177'F.
This operability
evaluation
had
been
reviewed
and concurred
in by the Manager of Nuclear
Engineering Services.
The inspector identified that
TS 3.8. 1.2,
Surveillance 4.8. 1.2, requires that, during Modes
5 and 6,
a diesel
generator
be capable of being loaded to greater
than or equal to 2484 kw.
The inspector
questioned
the validity of the operability assessment
based
on the
TS
electrical'loading
requirements.
The inspector also questioned
whether
any instructions
had
been provided to
operations
department
personnel
expected to initiate compensatory
actions for
generator
load conditions of greater
than
1400
kw.
Apparently,
no guidance
had
been provided to operators
even though vital component
loads
on the
associated
bus
had
been estimated
to be close to 1800
kw during Modes
5 and 6.
Guidance for load shedding
was provided to operators within 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> of the
inspector raising the issue.
The operability evaluation
was issued
and questioned
by inspectors
when the
Unit
1 core
was off-loaded
(No Mode).
Although the operability evaluation
documented it's applicability for Modes
5 and 6, the
TS requirements
were not
applicable at that time.
As a result of the concerns
raised
by the inspector,
the licensee
revised the
operability evaluation.
Licensee calculations
completed during the first week of April 1994,
concluded
that, with roll up doors
opened to provide air flow, diesel
performance
would
meet design basis
loading requirements
up to the maximum temperature
of 91'F
identified in the Final Safety Analysis Report.
During
a meeting
on April ll, 1994, to discuss
more detailed
aspects
of the
EDG air flow test results with the licensee,
NRC inspectors
raised the
following issues:
~
The need for issuing formal guidance
in procedures
to the operators
to
determine
which loads
should
be shed.
~
Apparently, the
EDG cooling air supply had not been tested
or calculated
for conditions
when more than
one diesel
is running.
This may not be
conservative,
since three diesels
may start
and all use the
same cooling
air source
when operators
open doors for extra cooling.
~
The calculated
basis for EDG oper ability during periods
when outside
ambient temperature
was greater
than S5'F relied
on
EDG operation with
engine jacket water temperatures
at 205 F, which is greater
than that
recommended
by the
EDG vendor (190'F).
The inspector questioned
whether
this condition was considered
acceptable
by the vendor.
Operability of EDGs depends
on operator actions to open roll-up doors
upon alarm of the diesel jacket water high temperature.
However, the
alarm circuit was not safety related
and does not undergo routine
surveillance to ensure it will perform it's required function.
Similarly, the roll-up doors were not qualified for design basis
functions.
Various design basis
scenarios
for the doors
and alarm
circuit had not been evaluated
regarding seismic, fire protection,
equipment qualification,
and control
room evacuation
requirements.
~
The capability for alarm circuit reflash
was not known, i.e., whether or
not
a separate
alarm on that circuit would preclude annunciation of a
jacket water temperature
{or other temperature)
alarm.
No acceptance
criteria appeared
to be stated for the cleanliness
of the
air pathways
in the
EDG radiators,
although debris in the radiators
may
ffect air flow through the radiator.
Several roll up doors were involved in supplying air to radiators;
however,
the doors required to be opened
were not identified clearly and
specifically.
It was not clear that appropriate
conservatism
was
used in the
calculations for the radiator
performance,
such
as dry air, wind
effects,
or other heat transfer conservatism.
It was not clear that the vendor
had concurred in the air flow and
diesel
performance calculations.
-10-
~
The licensee
had not shared air flow measurement
and radiator
performance
information with other licensees
with similar diesel
radiator designs.
~
Past surveillance test performance of diesel
generators
while air
temperatures
were above 78'F had not been reviewed to validate
operability calculations.
The licensee
provided satisfactory resolution of each of the above issues,
obtained
vendor concurrence
with performance
conditions
and expectations,
or
is performing detailed calculations
and evaluations to address
the concern.
Testing
was later performed with all three Unit
1
EDGs running, with
satisfactory air flow results.
Other licensee identified technical
issues
are
under review or undergoing calculations.
The information has
been
shared with
the industry.
The licensee
has initiated
a hot weather plan, to be effective
upon
alarm indication in the control
room for ambient temperature
greater
than
78oF
A search of past operations
during high ambient temperatures
indicated that,
during
a 7-hour run at 85'F ambient temperatures,
jacket water temperature
reached
and stabilized at 200'F,
which the vendor concurred
was acceptable
for
sustained
operation.
This satisfactory
EDG performance
occurred without
opening roll up doors.
3.3. 1
Conclusion
The licensee
appeared
to have promptly addressed
the operability issues.
However, inspectors
were able to identify several
potential
issues,
which
indicated
some weaknesses
in the completeness
of engineering
and technical
work.
Overall, licensee
engineering
involvement appeared
to be acceptable.
3.4
Flow Oscillations in
EDG Radiators
The licensee identified that air flow through the
EDG radiators
evidenced
pressure oscillations.
The fans were designed for a pressure
drop of
1.8 inches of water
and were installed in a configuration which resulted
in
approximately 2.4 inches of water.
The licensee
tested
fan blades at lower
angles to determine if oscillations could be reduced,
but minimal benefit was
gained,
and air flow was reduced.
The licensee
returned the blades to the
original configuration.
Detailed inspection of the blade
hubs
was performed,
and
no indications of
fatigue or growth of existing surface discontinuities
was identified.
Despite
the lack of fatigue indications,
the licensee
implemented
a previously
approved
design
change during the unscheduled
Unit 2 outage,
replacing Unit 2
EDGs fan hubs with more robust design
hubs.
This design
change
had already
been
performed
on Unit
1 during the scheduled
outage.
The licensee
concluded,
and obtained
vendor concurrence,
that continued operation of the
EDGs with
flow oscillations would not be detrimental
to long term
EDG operation.
3.4.1
Conclusion
The licensee
appeared
to have appropriately
addressed
these
issues
with
timely, intrusive engineering
involvement.
3.5
Reactor
Vessel
Level Indication
S stem
On April 20,
1994, during preparations
to perform
RCS maintenance
at reduced
inventory while at
an
RCS level of 109 feet
(RCS loops full, and
2 feet above
the midloop level of 107 feet), the licensee
found that the narrow range level
indicator,
LT 400, did not properly agree with the other narrow range
transmitter or the wide range transmitter.
Operations staff halted the
procedure for continuing to midloop operations
while the
RCS was at
109 feet,
until the level indication was repaired.
Licensee
management
of maintenance,
engineering,
and operations
became actively involved, along with plant staff,
in agreeing that operations
would remain halted until the problem was
resolved.
Troubleshooting
revealed that the indicator consistently
indicated
about
a
1.5-inch lag in actual level, resulting in the indicated level being
approximately 1.5 inches
high under conditions of decreasing
level,
a
nonconservative
indication.
The level indicator consisted of a reference
leg
in which
a float containing
a magnet
rose
and fell with reference
leg level.
The magnet
actuated
magnetic
sensors
outside the reference
leg, allowing
visual indication of the level.
The licensee
duplicated
the observed
oFfset
in a bench test
by changing the axial orientation of the float, resulting in
the magnet not facing the sensors
and changing the sensed
magnetic field.
Efforts to realign the float in the plant were not successful.
The lag offset
was consistently
repeated
during troubleshooting
in the plant,
and, after
contact with the vendor, plant Engineering,
Operations,
and Instrument
and
Control staff concluded that the indicator's calculated
instrument error
should
be increased
to include the observed error and procedures
revised
accordingly before entering midloop operations.
After revision of the
procedures
to raise the minimum level of the
RCS level midloop operating
band,
which resulted
in narrowing the operating
band,
operations
at reduced
inventory were initiated.
No further problems
were identified during reduced
inventory operations.
3.5. 1
Conclusion
Major work activities were halted
when plant management
concluded that further
investigation
and testing of the level indicated
was required.
This was
a
conservative
and responsible
approach
to plant safety during reduced
inventory.
0
-12-
4
PLANT MAINTENANCE
(62703)
During the inspection period,
the inspecto}
observed
and reviewed selected
documentation
associated
with maintenance
and problem investigation activities
listed below to verify compliance with regulatory requirements,
compliance
with administrative
and maintenance
procedures,
required quality
assurance/quality
control department
involvement,
proper
use of safety tags,
proper equipment
alignment
and use of jumpers,
personnel
qualifications,
and
proper retesting.
Specifically, the inspector witnessed
portions of the following maintenance
activities:
Unit
1
~ Diesel
Engine Generator
Inspection
(18-Month interval)
~ Inspection/Replacement
of 480 Volt Bus
G Insulators
~ IY-13 Cable Installation
and Termination
Unit 2
~ Replacement
of Safety Injection Vent Line
~ FCV-439 Motor Operator Inspection
~
EDG 2-1 Postmaintenance
Test
(PMT 27.21)
4. 1
Inverter IY-13 Installation
On April 4,
1994, during review of a work order which included connection of
wiring associated
with Inverter IY-13, the inspector noted that the foreman
verification of the clearance
had not been
signed for more than
1 week after
the start of the work,
and subsequent
work order steps
had
been performed.
The inspector questioned
the foreman in charge of the work, who indicated the
signature
should
have
been
made prior to starting the work.
Subsequent
review
of the work package
revealed that the foreman back-dated
his signature for
having verified the clearance
to March 26,
1994,
although the work order step
was signed
on April 4,
1994.
Discussions with licensee
management
revealed
that this situation did not meet their expectations.
The management,
however,
indicated that the foreman stated that
he had verified the clearance
prior to
starting the work and
had not signed the work package
at that time.
The inspector also inquired of the foreman
when the work was scheduled
to be
completed.
The foreman indicated that the work should
be completed within the
next several
hours.
While reviewing the work package,
the inspector
noted
that
a significant number of steps
had not been
signed
as complete.
The
inspector questioned
the foreman concerning
the lack of signatures.
The
0
-13-
foreman indicated that most of the work had
been
completed
but not signed for
and that
he was in the process of verifying the work which had
been
performed
by the other shift.
The inspector raised
the concern to licensee
management
regarding the lack of discipline of the involved workers in that they were not
completing sign-offs for their work as work was completed.
Additionally,
later review by the inspector
found that the dates for some of the recently
signed
steps
had
been
back-dated
to an earlier time.
The inspectors
were concerned that construction
workers
had not under stood
management
expectations
that steps
would be signed off as
soon
as they were
completed,
and dated
on the date they were signed,
rather than allowing steps
to be signed
days later
and dated
back to the date the step
was completed.
Licensee
management
expressed
concern that workers
had not understood
these
expectations,
particularly in light of past procedural
compliance
issues.
On
April 7,
1994,
a bulletin was issued to all nuclear construction
services
personnel
outlining the expectations
that steps
would be signed
and dated
as
soon
as practicable
upon completion of the step,
as well as the potential
safety
and work control
consequences
associated
with improper completion of
sign-offs.
The inspectors
questioned
whether the plant maintenance
personnel
were also fully aware of these expectations.
The licensee
stated that the
contents of the bulletin would be discussed
with plant maintenance
personnel
as well as construction
personnel.
These actions
adequately
addressed
the
inspector's
concerns.
4.1.1
Safety Significance
There is no safety significance specifically- associated
with the lack of a
signature for the clearance verification step,
since the
same clearance
number
and clearance
points
had
been
used to remove the old inverter,
IY-13, and the
step in that work order which required the foreman to walk down the clearance
had
been
perFormed
and signed
as complete at the start of the work.
The
construction
crew was
aware of that the
same clearance
was being
used in the
installation of the
new inverter.
4.1.2
Conclusion
The licensee
had not clearly conveyed expectations
associated
with timely sign
off and correct dating of work order steps.
Although the construction
work in
the field appeared
to have
been properly completed,
the inspector
identified
a
case of lack of sign off of a step
and late sign off and back-dating of some
steps of a work order which replaced
a safety-related
inverter.
The licensee
actions in response
to the concern
appeared
appropriate.
The safety
significance of these
specifsc findings was negligible, since work appeared
to
have
been
completed appropriately
and the identical sign off in a separate
work order referring to the
same clearance
had
been signed
by the foreman.
-14-
4.2
Re 1acement of Safet
In'ection
Accumulator 2-3 In'ection Vent Line
On March 31,
1994,
the inspector
reviewed operator logs
and interviewed the
shift supervisor following an unexpected
delay in the work schedule for the
replacement
of SI Accumulator 2-3 vent line.
The Shift Supervisor indicated
that the delay was caused
in part by the concern for hydrogen off-gassing
in
the
RCS and, later,
by presence
of a vacuum in the vent line which was
observed after removal of the vent line pipe cap.
The delay was
due to
concerns
regarding the potential for introduction of material into the
while the pipe was being cut with the presence
of a vacuum in the pipe.
Subsequent
discussion
with the Directors of the Operations
and Mechanical
Maintenance
Departments
revealed that no clearance
had
been
used to perform
the leak repair.
A clearance
had been written by the work planning group for
the performance of the work but was not used.
The decision to not implement
a
clearance for performance of the work was
made at the prejob briefing by
Operations
Department
personnel.
This is
a violation of the work procedure.
The Operations
and Mechanical
Maintenance
managers
said that the decision to
not set the clearance
was based
on concern
over disturbing the failed weld for
analysis.
As a result, residual
heat
removal
{RHR) cold leg injection to
Loops
3 and
4 was not isolated
from the maintenance
area
and flow past the
safety injection pipe penetration
created
a vacuum in the vent line.
An additional
concern
over the need to purge hydrogen from the vent line had
been raised at the prejob briefing.
Individuals in the prejob briefing
decided to remove the hydrogen
from the line by establishing
an inert gas
purge prior to cutting the pipe.
The use of a nitrogen purge
was then
discussed
with the Mechanical
Maintenance
manager
and agreed
upon.
Subsequent
to the discussion,
personnel
involved with the work decided to use
as
the purge gas.
Argon was readily available,
since it was planned to be used
as
a cover gas during the welding,
and necessary
hoses
and regulators
were
already
staged
at the work site.
Management
was not consulted following the
decision to use
as the purge gas.
The argon purge
equipment
was connected
and purging was
commenced
at
a rate of 50 cubic feet
per hour.
No instructions specifying the use,
connection,
or removal of argon
purge equipment
were issued.
After purging argon for approximately
40
minutes,
the welding personnel
questioned
the continued existence of a
negative
pressure
in the vent line and contacted
operations
personnel
to
investigate.
Operations
personnel
then told the welders to secure
the purge
and investigated
the cause of the
vacuum in the line.
It was determined that
Loop
3
RHR flow past the SI pipe connection
was creating the negative
pressure
in the vent line.
Valve RHR-2-8809B, which was initially planned to be shut
in accordance
with the unimplemented
clearance,
was then shut.
This secured
RHR flow to Loops
2 and
3 and eliminated the
vacuum in the vent line.
Work to
replace
the vent line was then
resumed.
During restart operations,
removal of argon from the
RCS was performed
by
filling and venting the volume control tank.
-15-
4.2.1
Conclusion
Investigation of the work activities revealed that there
was confusion over
the maintenance activity requirements
in several
areas
which contributed to
failure to set the proper clearance
for the work and the improper use of argon
as
a purge gas.
In cases
where
a purge is required,
the work order normally
specifies
the installation
and removal of purge equipment.
The inspector
questioned
the lack of a clearance
and the adequacy of both the planning
and
the procedures
for performing the work.
Personnel
involved in the decision to
use
as
a purge
gas were not aware of the potential radiological
consequences
due to the high energy activation of argon after it is exposed
to
a neutron flux.
The failure of the licensee
to implement the required clearance,
thus allowing
gas into the
RCS,
was
a violation of TS 6.8. I, which requires that
procedures
be implemented for the
recommended
processes
of Regulatory
Guide 1.33.
Regulatory
Guide 1.33,
paragraph 9.a.,
recommends
that procedures
associated
with maintenance
of equipment
important to safety
be properly
preplanned
and controlled (50-323/94-11-01).
5
SURVEILLANCE OBSERVATIONS
(61726)
Selected
surveillance tests
required to be performed
by the
TS were reviewed
on
a sampling basis to verify that:
(1) the surveillance tests
were correctly
included
on the facility schedule;
(2)
a technically adequate
procedure
existed for performance of the surveillance tests;
{3) the surveillance tests
had
been
performed at
a frequency specified in the Technical Specifications;
and
{4) test results satisfied
acceptance
criteria or were properly
dispositioned.
Specifically, portions of the following surveillances
were observed
by the
inspector
during this inspection period:
Unit
1
~ Reactor Cavity Hanipulator Crane
~ Diesel
Generator
Radiator Air Flow
Unit 2
~ Control
Room Ventilation Functional
Test
5. 1
Surveillance of Reactor Cavit
Mani ulator Crane
During routine inspection activities, the inspector
reviewed documentation
of
replacement
of several
relays in the motor circuitry of the refueling
manipulator crane
(WO C0121933).
Although the crane is not safety related, it
is controlled
by TS,
and it's function of lifting and moving reactor fuel is
important to safety.
The inspector questioned
whether the crane
had
been
returned to service without performance of a formal surveillance test.
After
completion of relay replacement,
the crane
vendor
and reactor engineers
had
informally performed parts of an integrated
crane
performance test,
Procedure
STP H-27,
"Fuel Handling System Interlock Verification and
Functional Test,"
and maintenance
personnel
had performed required
postmaintenance
testing of the relay circuity and motor circuits.
Reactor
engineers
and engineering
management
explained that,
since
none of the relays
associated
with the
TS required overload
and underload circuitry (associated
with fuel lift) had
been replaced,
the operability of the crane did not
require formal surveillance testing.
Surveillance Test N-27 was performed in
a formal manner later,
as
a conservative
measure.
The inspector identified that the formality of the control of crane
operability was less
than desirable,
since the clearance
to remove the crane
from service for relay replacement
had referenced
the
TS surveillance test,
performed several
days earlier
on the
TS underload
and overload interlock
circuits,
as the basis for returning the crane to operable
status after the
relay replacement.
This was not appropriate
documentation
of equipment
oper ability, and engineering
management
agreed that proper formal
documentation of operability would be discussed
with engineering staff.
An additional
concern
was identified by the inspector.
During preparation of
some work orders, identification of applicable
postmaintenatrce
surveillance
test requirements
may be inadequate.
Planners
determine
the need for a
surveillance test
by determining if the equipment is safety related or listed
in Equipment Control Guidelines,
developed for administrative control of
important equipment
which is not listed in TS.
The inspector pointed out that
surveillance
requirements
for equipment
which is not safety related but is
included in TS would not be readily identified.
The licensee
acknowledged
this vulnerability,
and documented this in an action request,
for correction,
5. 1. 1
Conclusion
The Reactor
Engineering evaluation of the
TS requirements
and the effect of
the maintenance
on the reactor cavity manipulator crane operability appeared
to be technically adequate,
although the formality of documentation
was not in
accordance
with management
expectations.
6
SAFETY SYSTEM WALKDOWN, 125
V DC SYSTEM
(71710)
The inspector reviewed the Final Safety Analysis Report,
TS,
and design
control
memorandum
(OCN S-67) ensuring there
was consistency
between
the
different documents.
TS surveillance
requirements
were reviewed along with
the surveillance
procedures
which accomplished
them.
The modifications to the
125
V DC system being performed during the Unit I outage
were discussed
with
the system engineer
concerning
the scope of the modifications, alternate
power
supplies,
and the changes
to emergency
procedures
associated
with the
modifications.
One administrative discrepancy
was found wher e the design
control
memorandum
referenced
a
TS table which did not exist.
This
discrepancy
was pointed out to the licensee.
The licensee initiated an action
-17-
request
to track correction of the deficiency.
Inspectors
walked down safety-
related
125
V DC circuitry in Unit
1 containment
and in the auxiliary building
to evaluate
the condition
and locations of selected
125
V DC circuitry.
The
inspectors
performed
a visual inspection of the internals of two battery
chargers
and
a
125
V DC distribution panel.
No deficiencies
were noted.
6. 1
Conclusion
The
125
V DC system
appeared
to be in good order
and the system engineer
appeared
knowledgeable.
7
PREPARATIONS
FOR REFUELING
(60705)
The inspectors
reviewed the licensee's
preparations
for refueling to determine
if adequate
safety
and procedural
control
was properly implemented
in
preparation for refueling.
The inspectors
examined surveillance test
completion,
equipment
checkouts,
fuel handling
and inspection operations,
shift manning requirements,
crew briefings, prerequisite lists,
outage safety
planning, control of reactivity, quality oversite
involvement,
and other
areas.
The inspectors
also examined preparations
for fuel movement in the
containment refueling areas,
the fuel handling building,
and the control room.
The licensee
procedures,
outage planning,
and training addressed
control of
reactivity, fuel inventory,
movement of fuel modules,
communications
between
refueling crew, control
room crew, fuel handling building crew and reactor
engineering monitors.
The engineering
and control
room staff had
been trained
and appeared
to have the tools to maintain rigorous control of the observed
evolutions.
7. 1
Conclusion
The preparations
for refueling appeared
well planned
and appropriate.
8
REFUELING OPERATIONS
{60710)
8. 1
Overview
The inspectors
observed refueling operations
to evaluate
the control of fuel
modules
and reactivity, refueling equipment operability, effectiveness
of
procedures
and communications,
and overall safety of fuel manipulations
and
reactivity control.
All of these
areas
appeared
to be effectively
implemented.
8.2
Nonconservative
Fuel Handlin
Practices
In one instance,
when
a fuel module was being loaded into Core Location F-8
with difficulty, a reactor
engineer
observed
the refueling crew place the
difficult module to the side
and place
a different fuel module in Core
Location F-8, to determine if the original module
was
bowed.
The reactor
engineer
immediately identified that,
by procedure,
no module
may be loaded
into
a location next to other modules
unless it is in that module's final core
0
-I8-
location.
Additionally, the reactor engineer identified that the control
room
had not been
informed that the
new module
was to be tried in Core
Location F-8, which was
a violation of the intent of the procedure to have the
control
room staff aware at all times of what fuel module moves were to occur.
These
concerns
were promptly documented
in Action Request
336402.
It was later discovered that the refueling crew in containment
had discussed
the
use of the next fuel module
as
a test for a bowed module
and determined
that placement of the fuel in Core Location F-8 would not violate intent of
the refueling procedure,
since the module would not be loaded,
since it would
not be unlatched.
The refueling crew was
aware that the reactivity control of
this temporary module configuration
was within TS and
bounded
by core
analysis,
assuming
the existing boron concentration of the refueling cavity.
The inspector discussed
the fuel movement issue with reactor engineering
management,
who considered that the refueling crew should
have informed the
control
room of the intended
movements of fuel, regardless
of the intent to
not unlatch the module in Core Location F-8.
Also, licensee
management
considered
that
a dummy module should
have
been
used rather than
a new fuel
module to test for bowed fuel to minimize the chance of damage to fuel
modules.
The movement of the
new fuel to Control Location F-8 determined that the
module
was not bowed.
were halted,
and closer inspection
found
a I/O-inch fastener
on the lower core plate which had interfered with
fuel alignment.
The fastener
was retrieved,
and inspection for additional
foreign material
was conducted.
No additional material
was identified.
The
fastener
was activated,
indicating that it had
been irradiated for at least
one cycle.
The licensee
concluded that
no fastener
of this design
was
used in
any safety-related
application,
and it had not detached
from reactor coolant
system internals.
The identification of the source of the fastener is
continuing.
8.2. 1
Conclusion
The safety significance of the placement of fuel in Core Location F-8 was
minimal, since the reactivity analysis
was bounded,
and the refueling crew was
fully aware of the negligible reactivity consequences
of this. fuel movement.
Though licensee
management
expectations
for communications
and control of fuel
movement
and
use of dummy modules to minimize the chance of fuel
damage
were
appropriate
and were communicated
to refueling crews,
the crew did not meet
these
expectations.
The resolution of the fastener
on the core support plate
was being resolved appropriately.
8.3
Conservative
Res
onse to Elevated
Counts
on
a Source
Ran
e Channel
On two occasions
the inspector
observed
licensee
operations
personnel
suspend
refueling operations
due to elevated
counts
on one of the source
range nuclear
instrumentation
channels.
Refueling operations
in both instances
remained
secured until the source
range
channel
level returned to its reference level,
0
-19-
in agreement
with the other channel.
The licensee initiated actions to
determine
and resolve the cause of the elevated
counts in both instances.
The
signal
on the source
range circuit appeared
to have
been
low level electrical
interference.
However,
were not resumed until the circuit
was clear.
8.3. I
Conclusion
The response
to elevated
counts
on
a source
range
channel
during refueling
operations
was conducted
in an appropriately conservative
manner.
9
OUALITY OVERSITE
(40500)
The inspector reviewed findings of quality oversite group audits
and
surveillances
to determine if the audits were sufficiently probing
and
implemented conservative
safety expectations.
Separate
issues
are discussed
below.
9. I
Ins ections
During an audit of snubber inspections,
the licensee quality organization
identified that
some
had not been visually inspected
as required
and
had
been declared
operable without conclusion of the visual portion of the
inspection,
without signing off the step requiring completion of the visual
inspection.
The corrective action involved completing visual inspection
and
counseling
mechanical
maintenance
management
and staff on proper documentation
and completion of safety-related
work.
No significant safety issues
were
identified.
9.2
Refuelin
Crew Activities
A quality oversite surveillance identified that the refuelling crew involved
in the improper location of the fuel module in the core location, discussed
earlier,
had also
been involved in the lack of proper foreign material
exclusion postings described
in an earlier report
and in
a miscommunication
regarding identification of specific fuel module designations
during receipt
inspection fuel handling.
Further review of the root cause of the
communication
issues
was initiated
by the Independent
Safety Engineering
Group
to determine if a
common thread
and corrective action could be identified for
this refueling crew.
9.3
Motor-0 crated
Valve Motor Pinion
Ke
Ins ections
was issued to address
a
10 CFR Part 21 identified
vulnerability in motor-operated
valves in which motor pinion keys
may not have
been properly installed.
The Plant Staff Review Committee
and the Independent
Safety Engineering
Group identified that the scope of inspection of valves
and
the identification of vulnerability of specific valves
was not conservatively
addressed
in the evaluation.
Subsequent
inspections
and discussions
with
licensee
management
resulted
in additional
valves being inspected,
and
one
key
0
-20-
was found operable
but improperly installed in a valve inspected
as
a result
of the quality group's
involvement.
9.4
Ins ection for Crackin
of 480
V Transformers
The potential for cracking of insulators
in 480
V transformer s was identified
and inspections
were conducted.
The guality Control staff identified that,
because
of mechanical
interferences
and minor accumulated
dust,
the
inspections
could be conducted without adequate visibility to identify
cracking
on the top and sides of the insulators.
Intrusive involvement by gC
resulted
in removal of the layer of dust
and improving the visibility of the
insulators.
Further involvement by the
NRC regarding crack acceptance
criteria,
and lack of identification of potential root causes
for the
cracking,
led to Engineering performing
a calculation concluding that the
insulators
were sufficiently supported to perform their safety function under
design basis conditions despite
the cracks.
9.5
Tem orar
Attachments in Containment
During an audit of containment
work practices,
guality Assurance staff noted
that several
temporary attachments,
such
as electrical
extension
cords,
service air,
and other temporary service connections
not being properly
attached to supports
and attached
to inappropriate
supports,
such
as
instrumentation lines
and other plant equipment.
The guality Assurance staff
took steps to identify improperly routed attachments
and informed the work
crews
and applicable
management
of the improper practices.
This resulted in
correction of improper work practices
and re-emphasizing
management
expectations
regarding
work in containment.
9.6
Conclusion
Each of these
issues
were of low safety significance.
However, the
involvement of quality oversite groups
was intrusive, timely,
and
conservative.
Corrective action appeared
timely and commensurate
with safety
significance.
As
a result of involvement
by the quality groups,
the safety
performance of the plant was improved.
10
FOLLOWUP ON CORRECTIVE ACTIONS FOR VIOLATIONS
(92901)
)0. 1
Closed
Violation 275 93-32-01
Failures to Follow Procedures
The
NRC identified four instances
of the licensee's
failure to follow
procedures,
which was issued
as
a citation with NRC Inspection
Report 50-275/93-32.
In a letter dated
February 4,
1994, the licensee
acknowledged
the violation and stated that corrective action
had
been
completed for the specific violations cited
and that corrective action
had
been initiated for the overall
concern of failure to follow procedures.
For
each of the specific instances
of failure to follow procedures,
the licensee
documented
actions which addressed
the concern.
The licensee
stated that
these
actions
would correct the identified violation and help preclude future
-21-
violations.
The inspector
reviewed
and verified these
actions.
The
licensee's
actions
appeared
to be appropriate
and properly implemented.
ll
IN-OFFICE REVIEW OF LICENSEE EVENT REPORTS
(90712}
The following licensee
event reports
were closed
based
on in-office review:
~
275/94-04,
Revision
0
Main Steam Safety Valves Outside Design
Bases
Due to Vendor Identified Deficiency
~
275/94-05,
Revision
0
Failure to Control Reactor
Vessel
Inventory During Draindown
Due to
Personnel
Error
ATTACHMENT 1
1
PERSONS
CONTACTED
l. 1
Licensee
Personnel
G.
H.
Nucl
J.
D.
Cany
W.
H.
Tech
- R. P.
- J. S.
- G. H.
R.
N.
- W. G.
S.
R.
"R. D.
- T. L.
- B. W.
P.
B.
- C. R.
- J. A.
R.
W.
- J.
R.
- K. A.
M. E.
- D. B.
- J f
- T. A.
P. T.
D.
H.
- S.
R.
P.
G.
R. A,
- J ~ A.
D.
P.
- D. A.
E.
R.
1.2
NRC Personnel
Rueger,
Senior Vice President
and General
Manager,
ear
Power Generation
Business
Unit
Townsend,
Vice President
and Plant Manager,
Diablo
on Operations
Fujimoto, Vice President,
Nuclear
nical Services
Powers,
Manager,
Nuclear guality Services
Bard, Director, Mechanical
Maintenance
Burgess,
Director,
Systems
Engineering
Curb,
Manager,
Nuclear Technical
Services
Crockett,
Manager,
Technical
and Support Services
Fridley, Director, Operations
Glynn III, Supervisor,
guality Assurance
Grebel,
Supervisor,
Regulatory Compliance
Giffin, Manager,
Maintenance
Services
Grable,
Engineer,
Mechanical
Maintenance
Groff, Director, Plant Engineering
Hays, Director, Onsite guality Control
Hess, Assistant Director, Onsite Nuclear Engineering Services
Hinds, Director, Nuclear
Safety Engineering
Hubbard,
Engineer,
Regulatory
Compliance
Leppke, Assistant
Manager,
Technical
Services
Hiklush, Operations
Manager,
Acting Plant Manager
Holden, Director, Instrumentation
and Controls
Houlia, Assistant to Vice President,
Plant Management
Nugent,
Engineer,
Regulatory Compliance
Oatley, Director, Materials Services
Ortore, Director, Electrical Maintenance
Sarafian,
Senior Engineer,
Nuclear guality Services
Savard,
Director, Technical
Services
Shoulders,
Director, Onsite Nuclear Engineering Services
Sisk, Senior Engineer,
Regulatory
Compliance
Taggart, Director, Onsite guality Assurance
Willis, Engineer,
Mechanical
Haintenance
- M. Hiller, Senior Resident
Inspector
H. Tschiltz, Resident
Inspector
J. Winton,
NRR Inspector Intern
In addition to the personnel
listed above,
the inspectors
contacted
other
personnel
during this inspection period.
- Denotes personnel
that attended
the exit meeting.
2
EXIT MEETING
An exit meeting
was conducted
on April 22,
1994.
Ouring this meeting,
the
inspectors
reviewed the scope
and findings of the inspection.
The licensee
acknowledged
the inspection findings documented
in this report.
The licensee
did not identify as proprietary
any information provided to,
or reviewed by,
the inspectors.
0
ATTACHNENT 2
ACRONYNS
TS
Chemical
Volume and Control
System
emergency
diesel
generator
Local
Leak Rate Test
safety injection
Technical Specifications